Increasing fuel demands and decreasing fossil fuel reserves have renewed focus on previously neglected alternative and renewable fuel resources such as biogas, bitumen, and waste coal. Utilizing these resources, however, is technically and economically challenging due to high levels of contaminants such as sulfur. For instance, biogas desulfurization costs can be as high as 30% of its energy value, and standard biogas utilization systems generate hundreds of tons of sulfur-laden waste annually.
Biogas is the gas-phase product of the anaerobic digestion of organic matter, and it typically contains 50-75 vol. % methane (CH4), 25-40 vol. % carbon dioxide (CO2), 2-7 vol. % water vapor, and <2 vol. % oxygen and various contaminants including hydrogen sulfide (H2S), mercaptans, ammonia (NH3), halogenated species, and siloxanes. Biogas is commonly referred to by other names including swamp gas, landfill gas (LFG), and digester gas. When the composition of biogas is upgraded to a higher standard of purity, it is commonly referred to as renewable natural gas or biomethane.
Biogas is produced in significant amounts. According to the EPA, “the largest methane emissions come from the decomposition of wastes in landfills, ruminant digestion and manure management associated with domestic livestock, natural gas and oil systems, and coal mining. It is estimated that some 686.3 million CO2-equivalent tons of methane were released in the United States in 2009 with landfills accounting for 117 million tons and waste water treatment plants accounting for 24.5 million tons. The total greenhouse gas emissions from biogas are approximately twice those numbers considering the large amount of CO2 present in biogas as described above. Because of its large emission volume and the presence of toxic contaminants such as H2S and NH3, biogas is a significant pollutant that is subject to various Federal regulations. Although biogas is environmentally problematic, it is also an important alternative energy source. With a Lower Heating Value (LHV) ranging from 25 to 37.5 MJ/kg depending on its methane concentration, biogas has been classified as a medium-BTU fuel.
Because biogas is generated from biomass and solid waste, it is considered to be a renewable carbon-neutral fuel. In the past 10 years, biogas has become an increasingly important fuel resource, particularly due to depleting petroleum reserves and increased awareness of greenhouse gas emissions. Biogas is typically used for combined industrial heat and power generation or as a feedstock for the chemical industry. Once biogas is converted to biomethane through the necessary purification steps, it is used as a natural gas replacement in applications ranging from transportation fuels to advanced electricity generation applications. Among these applications, power generation and injection to the natural gas grid are the most common.
According to the EPA's Landfill Methane Outreach Program (LMOP), there are more than 500 landfill gas projects in the United States. Two thirds of these projects produce electricity and generate 13 billion kW-hours of electricity annually and one third supply 100 billion cubic feet of landfill gas to direct end users and natural gas pipelines annually at an annual market value of S1.7 billion. In Europe, biogas plants provided 8346 kiloton oil equivalents of biogas with an estimated value of $5.9 billion in 2009. Currently the world market for biogas productions is $8 billion per year (BPY).
Most recently, directly producing energy from biogas using fuel cells has attracted significant research effort because of technological advances in fuel cells. High-temperature fuel cells, especially Solid Oxide Fuel Cells (SOFCs), are ideal for energy generation from biogas due to their high tolerance to CO2 and contaminants such as sulfur, ammonia, and halogenated species which result in increased process simplicity. The fuel cell-based energy generation approach is advantageous because it can significantly reduce emissions while maximizing energy generation. Furthermore, with this approach, even small-scale landfills or waste water treatment plants can efficiently produce electricity. Besides its direct use as a renewable fuel, biogas is also a raw material for various gas-to-liquids (GTL) processes. GTL processes convert biogas to liquid fuels for easy storage and transportation.
The biogas applications described above are only viable if biogas contaminants are removed to below critical levels. This is of utmost importance for advanced power generation and fuel conversion processes where the contaminants can cause permanent damage to expensive system components. The most notorious biogas contaminants are sulfur species, which are primarily present as hydrogen sulfide (H2S) and secondarily present as carbonyl sulfide (COS), dimethyl sulfide (DMS), and mercaptans. These species can be present at levels up to a few volume percent, and at these levels, even directly using biogas as a heating fuel for large scale applications is subject to environmental protection regulations.
The presence of sulfur at a typical range of 1000-5000 ppmv will poison the electrocatalysts inside most fuel cells and most GTL catalysts. Fuel cells typically require fuel gas with a sulfur content less than 0.5 ppm for molten carbonate fuel cells (MCFCs) and less than 2 ppm for SOFCs and GTL produced by Fischer Tropsch synthesis typically requires <1 ppm sulfur to keep catalysts from poisoning. Due to the high sulfur content of the feedstock and low sulfur threshold for these applications, desulfurization is a critical step and accounts for 30% of the energy value of biogas resources according to the DOE. Other common biogas contaminants such as ammonia (NH3), siloxanes, and halogenated compounds also inhibit catalyst performance inside fuel cells and GTL units and cause corrosion and abrasion issues for the auxiliary components in various applications, especially compressed gas systems.
Various desulfurization technologies have been developed for different applications. According to the sulfur production scales, these technologies can be classified into three groups: large scale, medium scale and small scale.
For large-scale applications, amine scrubbing combined with the Claus reaction has been the most cost effective sulfur removal method. Most commercialized catalytic sulfur removal processes such as Shell's SulFerox® process and Merichem's LO-CAT® process have been used for medium-scale applications. These technologies convert H2S to elemental sulfur through liquid phase redox reactions using iron chelates as catalysts. Shell's Thiopaq®, similar to SulFerox®, is also a medium-scale process that oxidizes H2S to elemental sulfur with the assistance of bacteria. These processes, especially the LO-CAT® process, can remove sulfur from a stream containing a few hundred ppm H2S down to a few ppm H2S. However, because of the high catalyst cost associated with these processes and the cumbersome solid-liquid separations that are required, these approaches are not suitable for small-scale applications.
For small-scale (<100 kg sulfur per day) processes, water scrubbing and sorbent scavengers are typically employed. At the lower end of small scale, less than 50 kg sulfur per day, the spent solids or liquids that contain H2S are directly disposed of to further reduce cost. All sulfur removal processes for biogas plants worldwide with a raw gas capacity of 10-13,000 Nm3/hour are based on solid and liquid sorbents/scrubbers. A favorable standard biogas plant size is smaller, 500 kWe (estimated ˜335 Nm3/hour) due to the diversity of biogas resources. At this size, around 35 kg of sulfur must be removed per day assuming a 500 kWe system with 30% net efficiency and fed with biogas containing 50% methane and 3000 ppm of H2S. Water scrubbing and disposable solid/liquids have been most economical for most of these types of plants.
Adsorption and absorption have been the primary technological choices for biogas purification, using systems such as metal oxides (i.e., iron sponge), metal oxide slurries, activated carbons, and impregnated active carbons.
These adsorbents, however, typically have relatively low sulfur capacities, less than 0.1 g of sulfur/g of adsorbent. At this capacity, the annual consumption of adsorbent will be ˜125 metric tons or ˜200 m3 for the 500 kWe system. A similar approach that adds excessive iron salts to the digesters can result in low outlet sulfur concentrations from the digester so that no further desulfurization is needed. However, the annual iron chloride consumption at the recommended concentration (4 times the stoichiometric) is expected to reach 200 metric tons. This huge sorbent or chemical consumption makes these processes both chemical and labor intensive. Moreover, due to fluctuations in sulfur concentrations, extra sorbent has to be loaded for the worst possible cases, and most of these adsorbents are not regeneratable and have to be disposed of in accordance with state and/or federal regulations. For advanced biogas applications such as fuel cell based electricity production and GTL fuel production, other contaminants such as halogenated compounds and siloxanes have to be removed by adsorbents. All these factors lead to a large waste disposal burden for sulfur removal and biogas cleanup. An ironic aspect of the current desulfurization approaches is that the spent adsorbents will most likely be buried in landfills resulting in the production of high sulfur content biogas.
Recently membrane separation approaches have been explored for biogas purification. The membranes can provide a convenient method to separate both CO2 and H2O from biogas by the use of a membrane. However, both approaches simply separate H2S from biogas stream and they still need downstream processes such as adsorption or a Claus reactor to process the sulfur species that are concentrated, particularly if H2S flaring is not allowed. Therefore, membranes are not a viable option for biogas desulfurization due to the limitations of adsorption and Claus processes.
Direct H2S oxidation is perhaps the most promising approach to meet the biogas desulfurization needs, due to its low fixed investment cost and very low operational cost. Oxidative sulfur removal (OSR) is based on a catalytic process to convert H2S into elemental sulfur by air at low to moderate temperatures (100-400° C.), as shown by Equation 1.H2S(g)+0.5O2(g)→H2O(g)+⅛S8(g)  Equation 1
Some catalytic approaches developed for natural gas purification are able to oxidize H2S and mercaptans to elemental sulfur at 150 to 400° C. using niobium catalysts, activated carbon-based catalysts, iron catalysts, TiO2 catalysts, Bi—Mo catalysts, and Vanadium catalysts.
Although direct H2S oxidation catalysts have been shown to be effective for geothermal waste gas and petroleum gas, such catalysts face significant challenges for biogas desulfurization. One major challenge is their short life in the presence of biogas. Significant deactivation of catalysts that functioned well during associated gas was observed during a 70-hour landfill gas testing.
Most of the catalysts and promoters evaluated for oxidative desulfurization are based on metal oxides of Cu, Fe, Mg, Mn, Mo, Nb and V. These metal oxides can react with CO2 and halogenated compounds and form stable carbonates and halides such as FeCl2, FeCO3, MgCO3, MnCO3, MoCl2, CuCl2, NbCl4, NbCl5 and VCl4. Among them, NbCl5 and VCl4 are highly volatile in OSR conditions. Some catalyst supports also suffer from sulfate formation at high temperatures. The formation of these species changes the structure of the catalysts and results in catalyst deactivation. Deactivation can also occur due to liquid sulfur formation and accumulation inside the catalyst pores.
The short catalyst life of the catalysts above significantly affects the economics of the process. With the current catalyst life and cost, the combination of OSR and adsorption is not competitive compared with the adsorbent approach using the best available commercial adsorbents. As a result, no commercial OSR processes for biogas desulfurization have been reported.
Another major challenge for current approaches is the formation of SO2. Due to the presence of excessive amount of oxygen, which is typically necessary to achieve high H2S conversion, SO2 is typically formed when the catalysts described above are employed. Moreover, SO2 is more problematic than H2S because it leads to further sulfate formation on the catalyst active phase and sulfate formation inside the downstream gas clean-up units and even inside fuel cells, which are very difficult to regenerate or remove.
The major challenges discussed above significantly limit the commercialization of current catalysts and related processes. There exists a need for oxidative sulfur removal catalysts with longer catalyst life and high selectivity for elemental sulfur production biogas desulfurization.
Therefore, it is an object of the invention to provide catalysts for oxidative sulfur removal and methods of making and using thereof.
It is further object of the invention to provide catalysts for oxidative sulfur removal which can treat high sulfur content-containing fuel streams and have high contaminant tolerance.